There are large volumes of hydrocarbon gases that are produced and handled in refinery and petrochemical plants. Generally, these gases are used as fuel or as raw material for further processing. In the past, however, large quantities of these gases were considered waste gases, and along with waste liquids, were dumped to open pits and burned, producing large volumes of black smoke. With modernization of processing units, this method of waste-gas disposal, even for emergency gas releases, has been eliminated. Nevertheless, petroleum refineries are still faced with the problem of safe disposal of volatile liquids and gases resulting from scheduled shutdowns and sudden or unexpected upsets in process units. Emergencies that can cause the sudden venting of excessive amounts of gases and vapors include fires, compressor failures, overpressures in process vessels, line breaks, leaks, and power failures. Uncontrolled releases of large volumes of gases also constitute a serious safety hazard to personnel and equipment. A system for disposal of emergency and waste refinery gases consists of a manifolded pressure-relieving or blowdown system, and a blowdown recovery system or a system of flares for the combustion of the excess gases, or both. Many older refineries, however, do not operate blowdown recovery systems. In addition to disposing of emergency and excess gas flows, these systems are used in the evacuation of units during shutdowns and turnarounds. Normally a unit is shut down by depressuring into a fuel gas or vapor recovery system with further depressuring to essentially atmospheric pressure by
venting to a low-pressure flare system. Thus, overall emissions of refinery hydrocarbons are substantially reduced.
Refinery pressure-relieving systems, commonly called blowdown systems, are used primarily to ensure the safety of personnel and protect equipment in the event of emergencies such as process upset, equipment failure, and fire. In addition, a properly designed pressure relief system permits substantial reduction of hydrocarbon emissions to the atmosphere.
The equipment in a refinery can operate at pressures ranging from less than atmospheric to 1,000 psig and higher. This equipment must be designed to permit safe disposal of excess gases and liquids in case operational difficulties or fires occur. These materials are usually removed from the process area by automatic safety and relief valves, as well as by manually controlled valves, manifolded to a header that conducts the material away from the unit involved. One of the preferred methods of disposing of the waste gases that cannot be recovered in a blowdown recovery system is by burning in a smokeless flare. Liquid blowdowns are usually conducted to appropriately designed holding vessels and reclaimed. A blowdown or pressure-relieving system consists of relief valves, safety valves, manual bypass valves, blowdown headers, knockout vessels, and holding tanks. A blowdown recovery system also includes compressors and vapor surge vessels such as gas holders or vapor spheres. Flares are usually considered as part of the blowdown system in a modern refinery. The pressure-relieving system can be used for liquids or vapors or both. For reasons of economy and safety, vessels and equipment discharging to blowdown systems are usually segregated according to their operating pressure. In other words, there is a high-pressure blowdown system for equipment working, for example, above 100 psig, and low-pressure systems for those vessels with working pressures below 100 p i g . Butane and propane are usually discharged to a separate blowdown drum, which is operated above atmospheric pressure to increase recovery of liquids. Usually a direct-contact type of condenser is used to permit recovery of as much hydrocarbon liquid as possible from the blowdown vapors. The non-condensables are burned in a flare system. A typical pressure-relieving system for flaring operations used not only as a safety measure but also as a means of reducing the emission of hydrocarbons to the atmosphere. A typical installation includes four separate collecting systems as follows: (1) a low-pressure blowdown system for vapors from equipment with working pressure below 100 p i g , (2) a high-pressure blowdown system for vapors from equipment with working pressures above 100 psig, (3) a liquid blowdown system for liquids at all pressures, and (4) a light-ends blowdown for butanes and lighter hydrocarbon blowdown products. The liquid portion of light hydrocarbon products released through the light-ends blowdown system is recovered in a drum near the flare. A backpressure of 50 psig is maintained on the drum, which
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minimizes the amount of vapor that vents through a backpressure regulator to the high-pressure blowdown line. The high-pressure, low-pressure, and liquid- blowdown systems all discharge into the main blowdown vessel. Any entrained liquid is dropped out and pumped to a storage tank for recovery. Offgas from this blowdown drum flows to a vertical vessel with baffle trays in which the gases are contacted directly with water, which condenses some of the hydrocarbons and permits their recovery. The overhead vapors from the sump tank flow to the flare system manifold for disposal by burning in a smokeless flare system.
The design of a pressure relief system is one of the most important problems in the planning of a refinery or petrochemical plant. The safety of personnel and equipment depends upon the proper design and functioning of this type of system.
The consequences of poor design can be disastrous. A pressure relief system can consist of one relief valve, safety valve, or rupture disc, or of several relief devices manifolded to a common header. Usually the systems are segregated according to the type of material handled, that is, liquid or vapor, as well as to the operating pressures involved.
The several factors that must be considered in designing a pressure relief system are (1) the governing code, such as that of ASME (American Society of Mechanical Engineers); (2) characteristics of the pressure relief devices; (3) the design pressure of the equipment protected by the pressure relief devices; (4) line sizes and lengths, and (5) physical properties of the material to-be relieved to the system. In discussing pressure relief systems, the foIlowing terms are commonly used.
Relief Valve: A relief valve is an automatic pressure relieving device actuated by the static pressure upstream of the valve. It opens further with increase of pressure over the set pressure. It is used primarily for liquid service.
Safety Valve: A safety valve is an automatic relieving device actuated by the static pressure upstream of the valve and characterized by full opening or pop action upon opening. It is used for gas or vapor service.
Rupture Disc: A rupture disc consists of a thin metal diaphragm held between flanges.
Maximum Allowable Working Pressure: The maximum allowable working pressure (that is, design pressure), as defined in the construction codes for unfired pressure vessels, depends upon the type of material, its thickness, and the service condition set as the basis for design. The vessel may not be operated above this pressure or its equivalent at any metal temperature higher than that used in its design; consequently, for that metal temperature, it is the highest pressure at which the primary safety or relief valve may be set to open.
Operating Pressure: The operating pressure of a vessel is the pressure, in psig, to
which the vessel is usually subjected in service. A processing vessel is usually designed to a maximum allowable working pressure, in psig, that will provide a suitable margin above the operating pressure in order to prevent any undesirable operation of the relief valves. It is suggested that this margin be approximately 10 percent higher, or 25 psi, whichever is greater.
Set Pressure: The set pressure, in psig, is the inlet pressure at which the safety or relief valve is adjusted to open.
Accumulation: Accumulation is the pressure increase over the maximum allowable working pressure of the vessel during discharge to the safety or relief valve expressed as a percent of that pressure or pounds per square inch.
Over Pressure: Over pressure is the pressure increase over the set pressure of the primary relieving device. It is the same as accumulation when the relieving device is set at the maximum allowable working pressure of the vessel. When the set pressure of the first safety or relief valve to open is less than the maximum
allowable working pressure of the vessel the over pressure may be greater than 10 percent of the set pressure of the first safety or relief valve.
Blowdown: Blowdown is the difference between the set pressure and the reseating pressure of a safety or relief valve, expressed as a percent of a set pressure or pounds per square inch.
Lift: Lift is the rise of the disc in a safety or relief valve.
Backpressure: Backpressure is the pressure developed on the discharge side of the safety valves. Superimposed backpressure is the pressure in the discharge header before the safety valve opens (discharged from other valves).
Built-up Pressure: Built-up backpressure is the pressure in the discharge header after the safety valve opens.
Safety Valves
Nozzle-type safety valves are available in the conventional or balanced-bellows configurations. Backpressure in the piping downstream of the standard-type valve affects its set pressure, but theoretically, this backpressure does not affect the set pressure of the balanced-type valve. Owing, however, to imperfections in manufacture and limitations of practical design, the balanced valves available vary in relieving pressure when the backpressure reaches approximately 40 percent of the set pressure. The actual accumulation depends upon the manufacturer.
Until the advent of balanced valves, the general practice in the industry was to
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select safety valves that start relieving at the design pressure of the vessel and reach full capacity at 3 to 10 percent above the design pressure. This overpressure was defined as accumulation. With the balanced safety valves, the allowable accumulation can be retained with smaller pipe size. Each safety valve installation is an individual problem. The required capacity of the valve depends upon the condition producing the overpressure.
Rupture Discs
A rupture disc is an emergency relief device consisting of a thin metal diaphragm carefully designed to, rupture at a predetermined pressure. The obvious difference between a relief or safety valve and a rupture disc is that the valve reseats and the disc does not. Rupture discs may be installed in parallel or series with a relief valve. To prevent an incorrect pressure differential from existing, the space between the disc and the valve must be maintained at atmospheric pressure. A rupture disc is usually designed to relieve at 1.5 times the maximum allowable working pressure of the vessel. In determining the size of a disc, three important effects that must be evaluated are low rupture pressure, elevated temperatures, and corrosion. Manufacturers can supply discs that are guaranteed to burst at plus or minus 5 percent of their rated pressures. The corrosive effects of a system determine the type of material used in a disc. Even a slight amount of corrosion can drastically shorten disc life. Discs are available with plastic linings, or they can be made from pure carbon materials.
The discharge piping for relief and safety valves and rupture discs should have a minimum of fittings and bends. There should be minimum loading on the valve, and piping should be used with adequate supports and expansion joints. Suitable drains should be used to prevent liquid accumulation in the piping and valves.
Smoke is the result of incomplete combustion. Smokeless combustion can be achieved by: (1) adequate heat values to obtain the minimum theoretical combustion temperatures, (2) adequate combustion air, and (3) adequate mixing of the air and fuel. An insufficient supply of air results in a smoky flame. Combustion begins around the periphery of the gas stream where the air and fuel mix, and within this flame envelope the supply of air is limited. Hydrocarbon side reactions occur with the production of smoke. In this reducing atmosphere, hydrocarbons crack to
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elemental hydrogen and carbon, or polymerize to form hydrocarbons. Since the carbon particles are difficult to burn, large volumes of carbon particles appear as smoke upon cooling.
Side reactions become more pronounced as molecular weight and unsaturation of the fuel gas increase. Olefins, diolefins, and aromatics characteristically burn with smoky, sooty flames as compared with paraffins and naphthenes. A smokeless flame can be obtained when an adequate amount of combustion air is mixed sufficiently with the fuel so that it burns completely and rapidly before any side reactions can take place. Combustion of hydrocarbons in the steam-inspirated-type elevated flare appears to be complete.The air pollution problem associated with the uncontrolled disposal of waste gases is the venting of large volumes of hydrocarbons and other odorous gases and aerosols. The preferred control method for excess gases and vapors is to recover them in a blowdown recovery system and, failing that, to incinerate them in an elevated type flare. Such flares introduce the possibility of smoke and other objectionable gases such as carbon monoxide, sulfur dioxide, and nitrogen oxides. Flares have been further developed to ensure that this combustion is smokeless and in some cases nonluminous. Luminosity does attract attention to the refinery operation and in certain cases can cause bad public relations. There is also the consideration of military security in which nonluminous emergency gas flares would be desirable. It is important to note that the
hydrocarbon and carbon monoxide emissions from a flare can be much greater than those from a properly operated refinery boiler or furnace. Other combustion contaminants from a flare include nitrogen oxides. The importance of these compounds to the total air pollution problem depends upon the particular conditions in a particular locality.
Other air contaminants that can be emitted from flares depend upon the composition of the gases burned. The most commonly detected emission is sulfur dioxide, resulting from the combustion of various sulfur compounds (usually hydrogen sulfide) in the flared gas. Toxicity, combined with low odor threshold, make venting of hydrogen sulfide to a flare an unsuitable and sometimes dangerous method of disposal, In addition, burning relatively small amounts of hydrogen sulfide can create enough sulfur dioxide to cause crop damage or local nuisance.
Materials that tend to cause health hazards or nuisances should not be disposed of in flares. Compounds such as mercaptans or chlorinated hydrocarbons require special combustion devices with chemical treatment of the gas or its products of combustion.
The ideal refinery flare is a simple device for safe and inconspicuous disposal of waste gases by combustion. Hence, the ideal flare is a combustion device that burns waste gases completely and smokelessly.There are, in general, three types of flares:
elevated flares, ground-level flares, and burning pits. The burning pits are reserved
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for extremely large gas flows caused by catastrophic emergencies in which the capacity of the primary smokeless flares is exceeded. Ordinarily, the main gas header to the flare system has a water seal bypass to a burning pit. Excessive pressure in the header blows the water seal and permits the vapors and gases to vent a burning pit where combustion occurs. This is rarely practiced today, except for parts of South America and Eastern Europe.
The essential parts of a flare are the burner, stack, seal, liquid trap, controls, pilot burner, and ignition system. In some cases, vented gases flow through chemical solutions to receive treatment before combustion. As an example, gases vented from an isomerization unit that may contain small amounts of hydrochloric acid are scrubbed with caustic before being vented to the flare.
Elevated flares are the most commonly used system. Smokeless combustion can be obtained in an elevated flare by the injection of an inert gas to the combustion zone to provide turbulence and inspirate air. A mechanical air-mixing system would be ideal but is not economical in view of the large volume of gases typically handled.
The most commonly encountered air-inspirating material for an elevated flare is steam. Three main types of steam injected elevated flares are in use. These types vary in the manner in which the steam is injected into the combustion zone. In the first type, there is a commercially available multiple nozzle, as shown in Figure 1, which consists of an alloy steel tip mounted on the top of an elevated stack. Steam injection is accomplished by several small jets placed concentrically around the flare tip. These jets are installed at an angle, causing the steam to discharge in a converging pattern immediately above the flare tip. A second type of elevated flare has a flare tip with no obstruction to flow, that is, the flare tip is the same diameter as the stack. The steam is injected by a single nozzle located concentrically within the burner tip. In this type of flare, the steam is premixed with the gas before ignition and discharge.
A third type of elevated flare is equipped with a flare tip constructed to cause the gases to flow through several tangential openings to promote turbulence. A steam ring at the top of the stack has numerous equally spaced holes about 118 inch in diameter for discharging steam into the gas stream.
The injection of steam in this latter flare may be automatically or manually controlled. In most cases, the steam is proportioned automatically to the rate of gas flow; however, in some installations, the steam is automatically supplied at maximum rates, and manual throttling of a steam valve is required for adjusting the steam flow to the particular gas flow rate. There are many variations of instrumentation among various flares, some designs being more desirable than others.
Figure 1, Smokeless flare burner.
For economic reasons all designs attempt to proportion steam flow to the gas flow rate. Steam injection is generally believed to result in the following benefits: (1) Energy available at relatively low cost can be used to inspirate air and provide turbulence within the flame, (2) steam reacts with the fuel to form oxygenated compounds that burn readily at relatively low temperatures, (3) water-gas reactions also occur with this same end result, and (4) steam reduces the partial pressure of the fuel and retards polymerization. Inert gases such as nitrogen have also been found effective for this purpose; however, the expense of providing a diluent such as this is prohibitive.
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There are four principal types of ground level flare: Horizontal venturi, water injection, multijet, and vertical venturi. In a typical horizontal, venturi-type ground flare system, the refinery flare header discharges to a knockout drum where any entrained liquid is separated and pumped to storage. The gas flows to the burner header, which is connected to three separate banks of standard gas burners through automatic valves of the snap-action type that open at predetermined pressures. If any or all of the pressure valves fail, a bypass line with a liquid seal is provided (with no valves in the circuit), which discharges to the largest bank of burners. The automatic-valve operation schedule is determined by the quantity of gas most likely to be relieved to the system.
The allowable back-pressure in the refinery flare header determines the minimum pressure for the control valve and the No. 1 burner bank. On the assumption that the first valve was set at 3 psig, then the second valve for the No. 2 burner bank would be set for some higher pressure, say 5 psig. The quantity of gas most likely to be released then determines the size and the number of burners for this section.
Again, the third most likely quantity of gas determines the pressure setting and the size of the third control valve. Together, the burner capacity should equal the maximum expected flow rate. The valve-operating schedule for the system is set up as follows:( 1) When the relief header pressure reaches 3 psig, the first control valve opens and the four small venturi burners go into operation. The controller setting keeps the valve open until the pressure decreases to about 1-1 /2 psig; (2) When the header pressure reaches 5 psig, the second valve opens and remains open until the pressure drops to about 3 psig; (3) When the pressure reaches 6 psig, the third valve opens and remains open until the pressure decreases to 4 psig; (4) At about 7 psig, the gas blows the liquid seal.
Another common type of ground flare used in petroleum refineries has a water spray to inspirate air and provide water vapor for the smokeless combustion of gases. This flare requires an adequate supply of water and a reasonable amount of open space. The structure of the flare consists of three concentric stacks. The combustion chamber contains the burner, the pilot burner, the end of the ignitor tube, and the water spray distribitor ring. The primary purpose of the intermediate stack is to combine the water spray that it will be mixed intimately with burning gases. The outer stack confines the flame and directs it upward. Water sprays in elevated flares are not too practical for several resons. Difficulty is experienced in keeping the water spray in the flame zone, and the scale formed in the waterline tends to plug the nozzles. Water main pressure dictates the height to which water can be injected without the use of a booster pump. For a 100- to 250-foot stack, a booster pump would undoubtedly be required. Rain created by the spray from the flare stack is objectionable from the standpoint of corrosion of nearby structures and other equipment. Water is not as effective as steam for controlling smoke with